This application is a divisional of U.S. patent application Ser. No. 11/805,359, filed on May 22, 2007, entitled “Viscosified Fluids for Remediating Subterranean Damage,” and published as US 2008/0289827.
The present invention relates to fluids useful in subterranean operations, and more particularly, to viscosified fluids for use in remediating damage in a subterranean formation.
Treatment fluids may be used in a variety of subterranean treatments, including, but not limited to, stimulation treatments and sand control treatments. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component thereof.
One common production stimulation operation that employs a treatment fluid is hydraulic fracturing. Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid) into a well bore that penetrates a subterranean formation at a sufficient hydraulic pressure to create or enhance one or more cracks, or “fractures,” in the subterranean formation. “Enhancing” one or more fractures in a subterranean formation, as that term is used herein, is defined to include the extension or enlargement of one or more natural or previously created fractures in the subterranean formation. The treatment fluid may comprise particulates, often referred to as “proppant particulates,” that are deposited in the fractures. The proppant particulates, inter alia, may prevent the fractures from fully closing upon the release of hydraulic pressure, forming conductive channels through which fluids may flow to the well bore. The proppant particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like, among other purposes, to enhance conductivity (e.g., fluid or gas flow) through the fractures in which they reside. Once at least one fracture is created and/or enhanced and the proppant particulates are substantially in place, the treatment fluid may be “broken” (i.e., the viscosity of the fluid is reduced), and the treatment fluid may be recovered from the formation.
Other common production stimulation operations that employ treatment fluids are acidizing operations. Where the subterranean formation comprises acid-soluble components, such as those present in carbonate and sandstone formations, stimulation and/or damage removal is often achieved by contacting the formation with a treatment fluid that comprises an acid. For example, where hydrochloric acid contacts and reacts with calcium carbonate in a formation, the calcium carbonate is consumed to produce water, carbon dioxide, and calcium chloride. After acidization is completed, the water and salts dissolved therein may be recovered by producing them to the surface (e.g., “flowing back” the well), leaving a desirable amount of voids (e.g., wormholes) within the formation, which may enhance the formation's permeability and/or increase the rate at which hydrocarbons subsequently may be produced from the formation. One method of acidizing known as “fracture acidizing” comprises injecting a treatment fluid that comprises an acid into the formation at a pressure sufficient to create or enhance one or more fractures within the subterranean formation. Another method of acidizing known as “matrix acidizing” comprises injecting a treatment fluid that comprises an acid into the formation at a pressure below that which would create or enhance one or more fractures within the subterranean formation.
Treatment fluids are also utilized in sand control treatments, such as gravel packing. In “gravel-packing” treatments, a treatment fluid suspends particulates (commonly referred to as “gravel particulates”), and deposits at least a portion of those particulates in a desired area in a well bore, e.g., near unconsolidated or weakly consolidated formation zones, to form a “gravel pack,” which is a grouping of particulates that are packed sufficiently close together so as to prevent the passage of certain materials through the gravel pack. This “gravel pack” may, inter alia, enhance sand control in the subterranean formation and/or prevent the flow of particulates from an unconsolidated portion of the subterranean formation into a well bore. One common type of gravel-packing operation involves placing a sand control screen in the well bore and packing the annulus between the screen and the well bore with the gravel particulates of a specific size designed to prevent the passage of formation particulates. The gravel particulates act, inter alia, to prevent the formation particulates from occluding the screen or migrating with the produced hydrocarbons, and the screen acts, inter alia, to prevent the particulates from entering the well bore. The gravel particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like, among other purposes, to enhance conductivity (e.g., fluid flow) through the gravel pack in which they reside. Once the gravel pack is substantially in place, the viscosity of the treatment fluid may be reduced to allow it to be recovered. In some situations, fracturing and gravel-packing treatments are combined into a single treatment (commonly referred to as “FRACPAC™” fracturing treatments). In such operations, the treatments are generally completed with a gravel pack screen assembly in place with the hydraulic fracturing treatment being pumped through the annular space between the casing and screen. In this situation, the hydraulic fracturing treatment ends in a screen-out condition, creating an annular gravel pack between the screen and casing. In other cases, the fracturing treatment may be performed prior to installing the screen and placing a gravel pack.
Maintaining sufficient viscosity in the treatment fluids used in these operations may be important for a number of reasons. Maintaining sufficient viscosity is important in fracturing and sand control treatments for particulate transport and/or to create or enhance fracture width. Also, maintaining sufficient viscosity may be important to control and/or reduce fluid loss into the formation. At the same time, while maintaining sufficient viscosity of the treatment fluid often is desirable, it may also be desirable to maintain the viscosity of the treatment fluid in such a way that the viscosity also may be reduced easily at a particular time, inter alia, for subsequent recovery of the fluid from the formation.
To provide the desired viscosity, polymeric gelling agents commonly are added to the treatment fluids. The term “gelling agent” is defined herein to include any substance that is capable of increasing by chemical means the viscosity of a fluid, for example, by forming a gel. Examples of commonly used polymeric gelling agents include, but are not limited to, guar gums and derivatives thereof, cellulose derivatives, biopolymers, and the like. The term “derivative” is defined herein to include any compound that is made from one of the listed compounds, for example, by replacing one atom in one of the listed compounds with another atom or group of atoms, ionizing one of the listed compounds, or creating a salt of one of the listed compounds. To further increase the viscosity of a treatment fluid, often the polymeric gelling agent is crosslinked with the use of a crosslinking agent. Conventional crosslinking agents may comprise a borate ion, a metal ion, or the like, and interact with at least two gelling agent molecules to form a crosslink between them, thereby forming a “crosslinked gelling agent.” Treatment fluids comprising crosslinked gelling agents also may exhibit elastic and/or viscoelastic properties, wherein the crosslinks between gelling agent molecules may be broken and reformed, allowing the viscosity of the fluid to vary with certain conditions such as temperature, pH, and the like.
The use of polymeric gelling agents, however, may be problematic. For instance, polymeric gelling agents may damage subterranean formations. For example, polymeric gelling agents may leave an undesirable gel residue in the subterranean formation after use, which can impact permeability. The term “damage” is defined herein to include effects from any treatment operation or natural occurrence that have a negative impact on well productivity. Factors that may impact well productivity may include fracture conductivity, gravel pack conductivity, and/or formation permeability. The term “gel damage” is defined herein to include damage resulting from any gelling agent or gel residue. Other forms of damage that may be present in a well bore or formation may be caused by the presence of one or more of asphaltenes, paraffins, bacterial slime, scale, pipe dope, grease, heavy oil, combinations thereof, and derivatives thereof.
As a result, costly remedial operations may be required to clean up the formation, fracture face, and proppant pack. As used herein the term “proppant pack” is defined to include proppant in fractures, gravel packs, frac packs, and the like. The terms “remedial operations” and “remediate” are defined herein to include a lowering of the viscosity of gel damage and/or the partial or complete removal of damage of any type from a subterranean formation. Similarly, the term “remedial fluid” is defined herein to include any fluid that may be useful in remedial operations. Thus, as used herein, the terms “treatment” and “treatment fluid(s)” do not contemplate, and are distinct from, a remedial operation and remedial fluid(s).
Existing approaches to remediating gel damage in a subterranean formation typically rely on low viscosity, approximately 1 centipoise (“cP”), aqueous based solutions of oxidizers such as sodium hypochlorite. Low viscosity remedial fluids may be problematic in some instances. For example, placement of a low viscosity remedial fluid to treat gel damage in subterranean fractures may be difficult, or coverage for gel filter cake removal by a low viscosity remedial fluid may be low. Such difficulties with fluid placement or low levels of coverage may be caused, for example, by the tendency of low viscosity fluids to leak off to a more permeable section of the formation.
To combat perceived problems associated with polymeric gelling agents, foamed treatment fluids and emulsion-based treatment fluids have been employed to minimize residual damage, but increased expense and complexity often have resulted. Other approaches to problems presented by polymeric gel damage have focused on the use of polymeric gelling agents that cause less damage to a subterranean formation. Additionally, some treatment operations employ nonpolymeric gelling agents.